For a variety of reasons wells can have multiple strings. One more recent example involves steam assisted gravity drainage (SAGD) installations used to recover tar sands from shallow formations. These installations use wells in combination. An injection well extends horizontally through a formation and is used to deliver steam into the formation to get the tar sands into a flowing condition as the heat added reduces viscosity. The production well is also run horizontally in the same formation and is generally below the injection well. The heated tar sands, from the steam from the injection well, flow into the production well for removal to the surface and further processing.
FIG. 5 is the current way production wells are configured in SAGD service and illustrate the problem addressed by the present invention. FIG. 5 shows a producer well W having a top casing 10 that is sealed with cement 12 and an intermediate casing 14 sealed with cement 16. The intermediate casing 14 terminates at 18 and beyond that is open hole 20. A production string 22 has an electric submersible pump (ESP) 24 at its lower end. A slotted liner 26 extends into open hole 20 and is hung at hanger 28. There is a closed end 30 on the slotted liner 26. A guide string 32 extends from the surface 34 and within the slotted liner 26 and well into the open hole 20. An instrument string 36 runs beyond end 38 of the guide string 32. Instrument string 36 is sealed at the lower end 40 and inside of it are instruments and sensors 42 that can detect temperature, pressure or other well conditions. These sensors are protected in the instrument string 36 from the harsh conditions in the open hole portion 20. It is preferred to put the ESP 24 within the intermediate casing 32 rather than in the open hole portion 20 in the event the ESP 24 needs to be removed for any reason.
Those skilled in the art will appreciate that normally without steam injection, there is no flow in the producer well W. In order to make the tar sands flowable the producer well needs to be heated from the injector well and from steam delivered to the producer well. This is a very slow process that can take months. Once the producer well is at temperature it is full with steam and condensate. If the ESP 24 develops a problem and needs to be removed the well W first had to be killed with water added from the surface 34 before a wellhead (not shown) could be removed so that the ESP 24 could come out. If the wellhead were simply removed and the well W were still live, the condensate in the open hole 20 would experience a pressure reduction and flash to steam and come out at the surface 34 since the wellhead was no longer in position. This would create a very dangerous condition at the surface. The alternative now available is killing the well with fluid before taking off the wellhead so that the flashing of condensate doesn't occur at the surface and possibly injure personnel. The problem with killing the well is that it takes so long to reheat it after it cools and it potentially does not produce as well even after it is put back in service after a months long warm up.
The present invention seeks to provide a way to remove the ESP 24 without having to kill the well W. The downhole equipment is reconfigured to provide a seal between the casing and the slotted liner and another seal between the guide string and the inside of the slotted liner. The guide string features internal seal bores and a ported sub or a sleeve type valve that allows flow to the ESP for production but cuts off flow to the ESP when the concentric string which could hold instruments is moved with respect to its surrounding guide string. With the well isolated below the ESP the production string with the ESP at its lower end can be pulled without killing the well as will be explained in detail below.
U.S. Pat. No. 6,328,111 is relevant to inserting an ESP into a live well that has a single string.